Problems can occur when oil and gas are both present in the produced fluids. The gas can be present (and usually is) in a dissolved phase. During production, the pressure decreases. If pressure goes below the bubble point, gas will come out of solution causing flow reduction and possibly blockage of production. Further, if gas comes out of solution, hydrates might form, again leading to blockage or reduction of production. Turbulent flow in the oil and gas pipelines often results in the formation of a water-in-oil (W/O) emulsion. Small water droplets in the pipeline provide large total surface area for hydrate formation at the water/gas saturated oil interface, which can lead to full conversion of water to gas hydrate. Hydrate formation can begin with water being emulsified in the oil phase forming water-in-oil (W/O) emulsions. The water molecules form a network of hydrogen bonds around the gas molecules creating water cages. Gas hydrates, (also known as clathrate hydrates) are crystalline compounds in which small gas molecules such as methane, ethane, propane are enclathrated by hydrogen-bonded water molecules. Gas hydrates typically form at high pressure and low temperature (e.g. 10 MPa, 277 K for methane hydrates). At these conditions, hydrates can form and potentially plug subsea oil and gas pipelines. Since these hydrates disrupt flow, they are considered a nuisance and can cause considerably expense due to disruption of production. It is thus of particular interest to determine the water droplet size of an emulsion and to use this information to effectively prevent the formation of these hydrates. Since water droplet size of the emulsion provides information about the hydrate particle size in the slurry, it is crucial to determine the water droplet size in a W/O emulsion.
Other measurements are also important to determining the impact of hydrate slurry or plug formation. Emulsion properties can impact hydrate slurry/plug formation, i.e. whether the system is fully dispersed with all water emulsified in oil, or partially dispersed where water is emulsified in oil and a free water phase also exists, or water continuous. Thus, it is also crucial to determine water droplet size distributions (DSD) in an emulsion. Measurement of PVT properties of oil such as bubble point pressure, viscosity and water cut is crucial in reservoir performance evaluation. Downhole viscosity measurements require a special production logging tool which are time consuming and expensive. In many occasions, lack of proper sealing of the tool or sampling a non-productive portion of the wellbore results in a significant cost and waste of variable time. Also current production logging technologies measure the oil/water/gas ratios by sampling a very limited portion of the fluid using point wise sensors which suffer from inaccuracy due to the improper sampling of the fluid.
FIG. 1 (redrawn from Turner, D. J. Colorado School of Mines, 2006 and Turner, D. J et al., Chem. Eng. Sci. 2009, 64 (18), 3996. doi: 1110.1016/j.ces.2009.05.051) illustrates a conceptual schematic of hydrate formation in pipelines for an oil-dominated system (i.e. where oil is the continuous phase). Hydrate formation begins with water being emulsified in the oil phase forming a water-in-oil (W/O) emulsion. This emulsion may or may not be desirable depending on the size of the water droplets. Next, at appropriate pressure and temperature condition, a thin hydrate shell will grow around the water droplets. If the water droplet is in the μm size range, gas molecules are able to penetrate through the shell. In this case, hydrates will grow inward forming fully converted hydrate particles that can prevent hydrate agglomeration and pipeline blockage. However, this hydrate shells can create a gas diffusion barrier between the oil and the water phase if water droplets are bigger than μm size range. Then there will be capillary attraction forces between hydrate particles due to water bridging (from unconverted free water) that cause the particles to agglomerate forming large hydrate aggregates. Since these aggregates may then form a blockage in the pipeline, it is crucial to determine the water droplet size in an emulsion and eventually the hydrate particle size in a slurry. With this information, pipeline parameters can be changed and the necessary channels injected to prevent the formation of large hydrate aggregates.
There are several methods being employed by researchers and operators to determine droplet size of the emulsion such as microscopy, and Nuclear Magnetic Resonance (NMR). Each method has its own advantages and disadvantages. For instance, the microscopy imaging method is relatively simple and fast. The size of the droplet is measured by analyzing optical microscopy images of the emulsion. However, in this method, only a small sample of the emulsion is analyzed (e.g. ˜250 water droplets) and thus the method may not reflect the actual condition in pipelines. Another method to determine the DSD of emulsions is using NMR. This method has gained interest since it is non-destructive and can measure a considerable amount of sample.
Low field nuclear magnetic resonance (NMR) measurements are currently used to measure porosity, pore size distribution and fluid saturations in oil and gas producing wells at downhole conditions. Hydrogen relaxation in different fluids is the key to identify fluid type and saturation in the formation. Besides relaxation, NMR downhole tools are capable of measuring the fluid diffusion in oil, gas and water and differentiating between these fluids based on diffusion coefficient differences. Both the relaxation rate and the diffusion coefficient of fluids change when restricted in non-permeable boundaries such as rock grains, bubbles or droplets.
Thus, there is a need for a system and method that can be used to predict whether a hydraulic plug is forming in an emulsion or foam, and utilize this information to design an appropriate treatment protocol.